Galp Energia

Earnings Release • Oct 29, 2018

RESULTS THIRD QUARTER 2018

October 29, 2018 Investor Relations

1.		EXECUTIVE SUMMARY3
2.		EXPLORATION & PRODUCTION5
3.	REFINING & MARKETING7
4.		GAS & POWER 9
5.		FINANCIAL DATA11
	5.1.	Income statement 11
	5.2.	Capital expenditure 13
	5.3.	Cash flow14
	5.4.	Financial position and debt 15
	5.5.	Reconciliation of IFRS and RCA figures 17
	5.6.	IFRS consolidated income statement 19
	5.7.	Consolidated financial position 20
6.		BASIS OF PRESENTATION 21
7.		DEFINITIONS 22

1.Executive summary

• Cash Flow from Operations (CFFO) reached €343 m during the quarter, down 14% YoY, impacted by changes in working capital of €186 m. Free Cash Flow reached €87 m.
• Consolidated RCA Ebitda was €642 m, up 38% driven by the increased contribution from the E&P business.
• E&P: RCA Ebitda was €396 m, up €192 m YoY, benefiting from the increased production and higher oil and natural gas sale prices.

Average working interest (WI) production reached 103.8 kboepd, up 10% YoY, supported by the contribution from FPSO #7 in Brazil, running at plateau since April, and despite the concentration of planned maintenance activities in the quarter. It is worth highlighting the start of production in July from the first unit allocated to the Kaombo development, in Angola.

• R&M: RCA Ebitda was €195 m, down €20 m YoY, impacted by a lower contribution from the refining activity. Galp's refining margin was \$5.8/boe, down \$1.6/boe YoY, following the international refining environment, with raw materials processed also down driven by maintenance activities.
• G&P: RCA Ebitda reached €44 m, up €4 m YoY, supported by increased results from the power business.
• Group RCA Ebit amounted to €470 m, reflecting the Ebitda evolution. IFRS Ebit was €514 m, with the inventory effect accounting for €45 m.
• RCA net income was €212 m, up €55 m YoY, although impacted by higher taxes and financial results related to the mark-to-market of hedging derivatives and currency adjustments. IFRS net income was €235 m.
• Capex totalled €234 m, of which 81% was allocated to E&P activities, including the payment of the signing bonuses related to the acquisition of participating interests in Uirapuru and C-M-791 licenses, in Brazil.
• At the end of September, net debt was €1,899 m, with net debt to Ebitda at 0.9x.
• On October 23, FPSO #8 (P-69) started production in the Lula Extreme South area, in Brazil. This unit has a capacity to daily process up to 150 kbbl of oil and 6 mm³ of natural gas.

Considering the YTD performance, it is expected that FY2018 Ebitda reaches c.€2.3 bn and capex stands at c.€1.0 bn.

Financial data

€m (IFRS, except otherwise stated)

	Quarter						Nine Months
3Q17	2Q18	3Q18	Var. YoY	% Var. YoY		2017	2018	Var. YoY	% Var. YoY
466	628	642	175	38%	RCA Ebitda	1,310	1,725	415	32%
204	411	396	192	94%	Exploration & Production	554	1,100	546	99%
215	174	195	(20)	(9%)	Refining & Marketing	630	491	(139)	(22%)
40	34	44	4	9%	Gas & Power	105	112	7	7%
289	457	470	182	63%	RCA Ebit	745	1,205	460	62%
115	328	311	196	n.m.	Exploration & Production	269	849	580	n.m.
132	93	115	(17)	(13%)	Refining & Marketing	369	242	(127)	(35%)
36	29	39	3	9%	Gas & Power	90	96	6	7%
156	251	212	55	35%	RCA Net income	387	598	210	54%
154	330	235	81	53%	IFRS Net income	368	697	328	89%
(14)	11	(10)	(4)	(26%)	Non-recurring items	(49)	(38)	(11)	(22%)
12	68	34	22	n.m.	Inventory effect	30	137	107	n.m.
398	604	343	(55)	(14%)	Cash flow from operations	1,074	1,192	119	11%
217	217	234	17	8%	Capex	589	597	9	2%
164	398	87	(77)	(47%)	Free cash flow	448	514	66	15%
(44)	146	(153)	108	n.m.	Post-dividend free cash flow	25	22	(2)	(9%)
1,967	1,737	1,899	(68)	(3%)	Net debt	1,967	1,899	(68)	(3%)
1.2x	0.9x	0.9x	-	-	Net debt to RCA Ebitda	1.2x	0.9x	-	-

Operational data

	Quarter					Nine Months
3Q17	2Q18	3Q18	Var. YoY	% Var. YoY		2017	2018	Var. YoY	% Var. YoY
94.6	108.1	103.8	9.2	10%	Average working interest production (kboepd)	90.8	105.3	14.5	16%
92.4	106.7	102.3	9.9	11%	Average net entitlement production (kboepd)	88.9	103.9	15.0	17%
45.3	64.3	65.3	20.1	44%	Oil and gas average sale price (USD/boe)	44.4	63.1	18.6	42%
29.7	28.5	27.7	(2.0)	(7%)	Raw materials processed (mmboe)	85.8	81.1	(4.6)	(5%)
7.4	6.1	5.8	(1.6)	(21%)	Galp refining margin (USD/boe)	6.1	5.1	(1.0)	(16%)
2.4	2.2	2.4	(0.0)	(1%)	Oil sales to direct clients (mton)	6.7	6.6	(0.1)	(2%)
1,064	1,133	1,201	138	13%	NG sales to direct clients (mm3 )	3,264	3,559	295	9%
652	759	823	170	26%	NG/LNG trading sales (mm3 )	2,184	2,331	147	7%

Market indicators

		Quarter					Nine Months
3Q17	2Q18	3Q18	Var. YoY	% Var. YoY		2017	2018	Var. YoY	% Var. YoY
1.17	1.19	1.16	(0.01)	(1%)	Average exchange rate EUR:USD	1.11	1.19	0.08	7%
3.71	4.30	4.59	0.88	24%	Average exchange rate EUR:BRL	3.54	4.30	0.76	21%
52.1	74.4	75.2	23.1	44%	Dated Brent price (USD/bbl)	51.8	72.1	20.3	39%
(1.4)	(2.2)	(1.2)	0.2	13%	Heavy-light crude price spread1 (USD/bbl)	(1.5)	(1.6)	(0.2)	(13%)
17.1	22.2	26.9	9.8	58%	Iberian MIBGAS natural gas price (EUR/MWh)	20.9	23.8	2.9	14%
16.1	21.1	24.6	8.4	52%	Dutch TTF natural gas price (EUR/MWh)	17.3	22.2	4.9	28%
6.3	8.8	10.7	4.4	71%	Japan/Korea Marker LNG price (USD/mmbtu)	6.3	9.7	3.4	54%
5.6	2.4	3.2	(2.4)	(43%)	Benchmark refining margin (USD/bbl)	4.5	2.5	(2.0)	(44%)
16.4	16.6	16.9	0.6	3%	Iberian oil market (mton)	47.3	49.2	1.9	4%
8,387	7,898	7,793	(594)	(7%)	Iberian natural gas market (mm3 )	25,754	25,770	16	0%

Source: Platts for commodities prices; MIBGAS for Iberian natural gas price; APETRO and CORES for Iberian oil market; Galp and Enagás for Iberian natural gas market. ¹ Urals NWE dated for heavy crude; dated Brent for light crude.

2. Exploration & Production

€m (RCA, except otherwise stated; unit figures based on net entitlement production)

		Quarter				Nine Months
3Q17	2Q18	3Q18	Var. YoY	% Var. YoY		2017	2018	Var. YoY	% Var. YoY
94.6	108.1	103.8	9.2	10%	Average working interest production1 (kboepd)	90.8	105.3	14.5	16%
82.8	94.6	93.1	10.3	12%	Oil production (kbpd)	79.2	93.1	13.9	17%
92.4	106.7	102.3	9.9	11%	Average net entitlement production1 (kboepd)	88.9	103.9	15.0	17%
5.6	5.3	7.4	1.8	31%	Angola	6.2	6.1	(0.2)	(2%)
86.8	101.4	94.9	8.1	9%	Brazil	82.7	97.8	15.1	18%
45.3	64.3	65.3	20.1	44%	Oil and gas average sale price (USD/boe)	44.4	63.1	18.6	42%
4.2	6.1	6.1	1.9	46%	Royalties2 (USD/boe)	4.1	5.9	1.7	42%
7.5	7.7	9.0	1.5	21%	Production costs (USD/boe)	8.2	8.6	0.4	5%
12.3	10.2	10.5	(1.8)	(14%)	DD&A3 (USD/boe)	13.1	10.6	(2.5)	(19%)
204	411	396	192	94%	RCA Ebitda4	554	1,100	546	99%
89	83	85	(4)	(4%)	Depreciation, Amortisation and Impairments3	287	251	(36)	(13%)
-	-	-	-	n.m.	Exploration expenditures written-off4	-	-	-	n.m.
0	-	-	(0)	n.m.	Provisions	(2)	-	2	n.m.
115	328	311	196	n.m.	RCA Ebit	269	849	580	n.m.
115	328	311	196	n.m.	IFRS Ebit	267	849	582	n.m.
13	10	15	3	21%	Net Income from E&P Associates	29	39	10	33%

1 Includes natural gas exported; excludes natural gas used or reinjected.

²Based on total net entitlement production.

2 Includes abandonment provisions and excludes exploration expenditures written-off.

³ Effective from 1 January 2018, G&G and G&A costs, mainly related to the exploration activity, started to be accounted as operating costs of the period in which they occur, and ceased to be capitalised. The Successful Efforts Method (SEM) was applied retrospectively and the 2017 figures were restated for comparison purposes.

Operations

Third quarter

Average working interest production of oil and natural gas was 103.8 kboepd, of which 90% corresponded to oil production.

Production increased 10% YoY supported by the ongoing development of the Lula field in block BM-S-11 in Brazil, with FPSO #7 contributing at oil plateau levels. It is worth highlighting the planned maintenance activities during the quarter in FPSOs #1, #4 and #5, as well as in Route 1 of the gas export network.

Regarding Iara, in block BM-S-11A, the Extended Well Test (EWT) in the Sururu West area was concluded in early August, contributing with just 0.3 kbpd to the average quarterly production.

During the quarter, the drilling of the Guanxuma prospect was concluded in block BM-S-8. The drilling rig then proceeded to the Carcará North area, where it started drilling Carcará West, the first well in this area.

In Angola, WI production was up 14% YoY to 8.8 kbpd, driven by the start-up of the Kaombo North project during July. Net entitlement production increased 31% YoY to 7.4 kbpd.

Results third quarter 2018 October 29, 2018

Nine Months

During the first nine months of 2018, average WI production was 105.3 kboepd, a 16% increase YoY, driven mainly by the development

Nine months

to 103.9 kboepd.

Kaombo.

RCA Ebitda amounted to €1,100 m, up €546 m YoY, benefiting from increased production and average sale prices, and despite the lower USD.

of the Lula project in Brazil and the start-up of

Net entitlement production increased 17% YoY

Production costs increased €25 m YoY to €205 m, due to the higher number of operating units in Brazil and taking into account the maintenance activities during the period. In unit terms and on a net entitlement basis, production costs increased to \$8.6/boe.

Amortisation, depreciation charges and abandonment provisions amounted to €251 m, down €36 m YoY, benefiting from the reserves upwards revision at the end of 2017, namely in Brazil, and from the BRL depreciation. On a net entitlement basis, unit depreciation charges were \$10.6/boe, down \$2.5/boe YoY.

RCA Ebit was €849 m, up €580 m YoY.

The contribution of associated companies was €39 m during the first nine months of 2018.

Results

Third quarter

RCA Ebitda for the E&P business was €396 m, up €192 m YoY, on the back of increased production and higher average sale prices of oil and natural gas.

Production costs increased €19 m YoY to €73 m, impacted by maintenance works during the period. In unit terms, and on a net entitlement basis, production costs were \$9.0/boe, up \$1.5/boe YoY.

Amortisation and depreciation charges (including abandonment provisions) decreased €4 m YoY to €85 m, due to the reserves upwards revision at the end of 2017, and to the weaker BRL during the period. On a net entitlement basis, DD&A decreased from \$12.3/boe to \$10.5/boe, also benefiting from a higher dilution in production.

RCA Ebit was €311 m, up €196 m YoY.

3. Refining & Marketing

€m (RCA, except otherwise stated)

	Quarter						Nine Months
3Q17	2Q18	3Q18	Var. YoY	% Var. YoY		2017	2018	Var. YoY	% Var. YoY
7.4	6.1	5.8	(1.6)	(21%)	Galp refining margin (USD/boe)	6.1	5.1	(1.0)	(16%)
1.6	2.3	2.0	0.3	20%	Refining cost (USD/boe)	1.6	2.2	0.5	31%
(0.7)	0.2	0.0	0.7	n.m.	Impact of refining margin hedging1 (USD/boe)	(0.3)	0.2	0.6	n.m.
29.7	28.5	27.7	(2.0)	(7%)	Raw materials processed (mmboe)	85.8	81.1	(4.6)	(5%)
27.5	26.4	25.6	(1.9)	(7%)	Crude processed (mmbbl)	77.1	75.4	(1.7)	(2%)
4.9	4.7	4.5	(0.3)	(7%)	Total oil products sales (mton)	14.0	13.4	(0.6)	(4%)
2.4	2.2	2.4	(0.0)	(1%)	Sales to direct clients (mton)	6.7	6.6	(0.1)	(2%)
215	174	195	(20)	(9%)	RCA Ebitda	630	491	(139)	(22%)
82	81	80	(2)	(3%)	Depreciation, Amortisation and Impairments2	262	250	(12)	(5%)
1	0	0	(1)	(96%)	Provisions	(0)	0	1	n.m.
132	93	115	(17)	(13%)	RCA Ebit	369	242	(127)	(35%)
147	200	154	8	5%	IFRS Ebit	390	429	39	10%
2	(0)	1	(1)	(62%)	Net Income from R&M Associates	8	2	(6)	(73%)

¹Impact on Ebitda.

² Excludes impairments on accounts receivables, which started to be accounted in Ebitda in 2018.

Operations

Third quarter

Raw materials processed were 27.7 mmboe during the quarter, 7% lower YoY due to the start of planned maintenance in the Matosinhos refinery in late September. Crude oil accounted for 92% of raw materials processed, of which 89% corresponded to medium and heavy crudes.

Middle distillates (diesel and jet) accounted for 48% of production, gasoline for 23% and fuel oil for 15%. Consumption and losses accounted for 7% of raw materials processed.

Total product sales decreased 7% YoY, driven by lower exports considering the inventory build ahead of refining maintenance. Volumes sold to direct clients stood in line YoY at 2.4 mton.

Nine months

Raw materials processed were 81.1 mmboe, 5% lower YoY, also impacted by the planned maintenance of the hydrocracker (HC) in Sines during the first quarter. Crude oil accounted for 93% of raw materials processed, of which 86% corresponded to medium and heavy crudes.

Middle distillates accounted for 47% of production, gasoline for 23% and fuel oil for 16%. Consumption and losses accounted for 7% of raw materials processed.

Volumes sold to direct clients were 6.6 mton, with volumes sold in Africa accounting for 10%.

Results

Third quarter

RCA Ebitda for the R&M business decreased €20 m YoY to €195 m, impacted by a lower contribution from the refining activity.

Galp's refining margin was down YoY to \$5.8/boe, following lower margins in the international market, which were mainly due to a lower gasoline crack and a higher impact in consumptions and losses considering higher commodities prices.

Refining costs were up €6 m YoY and stood at €47 m, or \$2.0/boe in unit terms, to which contributed the start of maintenance in the Matosinhos refinery.

The marketing activity benefited from robust sales to direct clients.

RCA Ebit was €115 m, while IFRS Ebit increased to €154 m. The inventory effect was €40 m.

Nine months

Ebitda RCA decreased €139 m YoY to €491 m, mainly due to the lower contribution from the refining activity, and also impacted by the lag in pricing formulas.

Galp's refining margin stood at \$5.1/boe, compared to \$6.1/boe during the previous year, mainly due to a lower gasoline crack and as fuel oil was at a higher discount to Brent.

Refining costs stood at €147 m, up €20 m YoY, mainly due to the maintenance of the HC in the first quarter of the year. In unit terms, refining costs were \$2.2/boe.

Refining margin hedging operations contributed with €16 m during the period, compared to a loss of €26 m in the previous year.

The marketing activity maintained its positive contribution to results.

RCA Ebit was €242 m and IFRS Ebit increased to €429 m. The inventory effect was €158 m.

Non-recurring items amounted to €30 m and were mainly related to a litigation compensation inflow.

4. Gas & Power

€m (RCA, except otherwise stated)

	Quarter						Nine Months
3Q17	2Q18	3Q18	Var. YoY	% Var. YoY		2017	2018	Var. YoY	% Var. YoY
1,716	1,892	2,024	308	18%	NG/LNG total sales volumes (mm3 )	5,449	5,891	442	8%
1,064	1,133	1,201	138	13%	Sales to direct clients (mm3 )	3,264	3,559	295	9%
652	759	823	170	26%	Trading (mm3 )	2,184	2,331	147	7%
1,292	1,326	1,262	(29)	(2%)	Sales of electricity (GWh)	3,812	4,030	219	6%
348	349	331	(17)	(5%)	Sales of electricity to the grid (GWh)	1,192	1,044	(148)	(12%)
40	34	44	4	9%	RCA Ebitda	105	112	7	7%
31	22	30	(1)	(3%)	Supply & Trading	78	74	(5)	(6%)
10	12	14	4	47%	Power	26	38	12	44%
5	5	5	1	12%	Depreciation, Amortisation and Impairments1	14	15	2	12%
-	0	-	-	n.m.	Provisions	1	0	(1)	(99%)
36	29	39	3	9%	RCA Ebit	90	96	6	7%
30	20	29	(1)	(5%)	Supply & Trading	76	69	(6)	(8%)
6	9	10	4	79%	Power	15	27	12	84%
34	35	44	10	30%	IFRS Ebit	95	108	13	13%
25	25	24	(2)	(7%)	Net Income from G&P Associates	75	73	(3)	(4%)

¹ Excludes impairments on accounts receivables, which started to be accounted in Ebitda in 2018.

Operations

Third quarter

Total volumes of NG/LNG sold reached 2,024 mm³, up 18% YoY, following the increase in network trading volumes and in sales to industrial clients and to the electrical segment in Iberia.

Sales of electricity were 1,262 GWh, down 2% YoY, driven by the start of planned maintenance in the Matosinhos cogeneration unit.

Nine months

Sales of NG/LNG increased 8% YoY to 5,891 mm³, supported by the increase in network trading volumes and sales to the conventional segment, namely to industrial clients.

Trading volumes increased 7% YoY, with the increase in NG sales in the European hubs offsetting the fewer LNG trading volumes.

Sales of electricity increased 6% YoY to 4,030 GWh, on the back of the higher contribution from the marketing activity.

Results

Third quarter

RCA Ebitda increased €4 m YoY to €44 m, benefitting from stable Supply & Trading and increased contribution from Power.

Ebitda of the Power activity increased €4 m YoY to €14 m, mainly driven by the increase in the sale price of the energy produced.

RCA Ebit was €39 m, while IFRS Ebit totalled €44 m.

Results from associated companies reached €24 m, of which €7 m related to the equity interest in Galp Gás Natural Distribuição, S.A. (GGND).

Nine months

RCA Ebitda stood at €112 m YoY, up €7 m YoY, supported by higher results from the Power activity.

Ebitda for the Power activity increased €12 m YoY to €38 m, benefiting from a higher cogeneration contribution, whilst Supply & Trading decreased €5 m to €74 m.

RCA Ebit was €96 m, while IFRS Ebit was €108 m.

Results from associated companies stood at €73 m, of which €24 m related to GGND.

5.Financial data

5.1. Income statement

€m (RCA, except otherwise stated)

		Quarter					Nine Months
3Q17	2Q18	3Q18	Var. YoY	% Var. YoY		2017	2018	Var. YoY	% Var. YoY
3,891	4,546	4,540	649	17%	Turnover	11,513	12,977	1,464	13%
(2,967)	(3,394)	(3,382)	416	14%	Cost of goods sold	(8,806)	(9,726)	920	10%
(376)	(459)	(432)	56	15%	Supply & Services	(1,180)	(1,336)	155	13%
(86)	(72)	(87)	2	2%	Personnel costs	(233)	(241)	8	3%
11	9	8	(3)	(25%)	Other operating revenues (expenses)	31	62	31	n.m.
(7)	(2)	(5)	(2)	(28%)	Impairments on accounts receivable	(15)	(11)	(4)	(24%)
466	628	642	175	38%	RCA Ebitda	1,310	1,725	415	32%
479	741	686	207	43%	IFRS Ebitda	1,338	1,924	586	44%
(177)	(171)	(172)	(5)	(3%)	Depreciation, Amortisation and Impairments	(566)	(519)	(47)	(8%)
(1)	(0)	(0)	(1)	(96%)	Provisions	1	(0)	(2)	n.m.
289	457	470	182	63%	RCA Ebit	745	1,205	460	62%
301	570	514	214	71%	IFRS Ebit	769	1,404	635	83%
40	35	39	(1)	(3%)	Net income from associates	113	113	0	0%
(17)	36	(34)	(17)	n.m.	Financial results	(42)	(6)	36	86%
(19)	(9)	(18)	(0)	(2%)	Net interests	(59)	(39)	(19)	(33%)
18	13	3	(15)	(83%)	Capitalised interest	64	30	(34)	(53%)
5	(5)	(15)	(20)	n.m.	Exchange gain (loss)	(9)	(33)	(24)	n.m.
(18)	37	(7)	11	60%	Mark-to-market of hedging derivatives	(25)	43	69	n.m.
(3)	-	4	7	n.m.	Other financial costs/income	(13)	(6)	6	49%
312	529	475	163	52%	RCA Net income before taxes and non controlling interests	816	1,312	496	61%
(132)	(229)	(221)	89	68%	Taxes	(376)	(594)	218	58%
(41)	(124)	(117)	76	n.m.	Taxes on oil and natural gas production1	(170)	(329)	158	93%
(24)	(48)	(43)	19	76%	Non-controlling interests	(53)	(120)	67	n.m.
156	251	212	55	35%	RCA Net income	387	598	210	54%
(14)	11	(10)	(4)	(26%)	Non-recurring items	(49)	(38)	(11)	(22%)
142	262	201	59	42%	RC Net income	339	560	221	65%
12	68	34	22	n.m.	Inventory effect	30	137	107	n.m.
154	330	235	81	53%	IFRS Net income	368	697	328	89%

1 Includes SPT payable in Brazil and IRP payable in Angola.

Third quarter

RCA Ebitda increased 38% YoY to €642 m, due to a higher contribution from the E&P business, while IFRS Ebitda reached €686 m considering an inventory effect of €45 m.

RCA Ebit increased €182 m to €470 m, while IFRS Ebit reached €514 m.

Results from associated companies were €39 m.

Financial results were negative by €34 m, lower YoY mainly driven by a less favourable impact from the mark-to-market of refining margin hedging and FX differences related to the appreciation of the USD.

RCA taxes increased from €132 m to €221 m, following the higher operating results, mainly in the E&P business.

Non-controlling interests of €43 m were mainly attributable to Sinopec's stake in Petrogal Brasil.

Results third quarter 2018 October 29, 2018

RCA net income was €212 m, while IFRS net income was €235 m. Non-recurring items of €10 m relate to the extraordinary contribution to the energy sector.

Nine months

RCA Ebitda increased €415 m to €1,725 m, driven by a higher upstream production and increased oil and natural gas prices, and despite the lower USD.

RCA Ebit went up €460 m to €1,205 m, while IFRS Ebit increased to €1,404 m.

Results from associated companies stood at €113 m.

Financial results increased, despite being negative by €6 m. It is worth highlighting the higher impact from the mark-to-market related to refining margin hedging, and the decrease in net interests following the reduction in the cost of funding YoY.

RCA taxes increased €218 m YoY to €594 m, mainly due to higher taxes related to the production of oil and natural gas.

Non-controlling interests of €120 m were mainly attributable to Sinopec's 30% stake in Petrogal Brasil.

RCA net income reached €598 m, while IFRS net income was €697 m.

5.2. Capital expenditure

		Quarter
3Q17	2Q18	3Q18	Var. YoY	% Var. YoY		2017	2018	Var. YoY	% Var. YoY
184	176	188	5	2%	Exploration & Production	511	481	(30)	(6%)
1	71	117	116	n.m.	Exploration and appraisal activities	1	192	190	n.m.
182	105	71	(111)	(61%)	Development and production activities	509	289	(220)	(43%)
30	36	44	14	47%	Refining & Marketing	70	109	39	55%
2	5	0	(2)	(85%)	Gas & Power	6	7	0	3%
0	0	1	0	n.m.	Others	1	1	0	3%
217	217	234	17	8%	Capex1	589	597	9	2%

¹ Capex figures based on change in assets during the period.

Third quarter

Capex totalled €234 m during the quarter, of which 81% was allocated to the E&P business.

Capex of €117 m in exploration and appraisal activities was mainly related to the payment of signing bonuses for Uirapuru and C-M-791 licenses in Brazil, which totalled €103 m. It is also worth highlighting the drilling activities in Guanxuma and Carcará North in the Brazilian pre-salt.

Investment related to development and production activities was mainly allocated to the development of projects in BM-S-11 in Brazil and block 32 in Angola.

Nine months

Capex totalled €597 m during the period, of which 80% allocated to the E&P business.

Investment in development and production activities reached €289 m and was mainly allocated to activities in block BM-S-11 and block 32. It is also worth highlighting the investment in the Coral South project in Mozambique.

Investment in downstream activities (R&M and G&P) reached €115 m and was mostly allocated to the maintenance and improvement of refining energy efficiency, as well as to the renewal of the retail network.

5.3. Cash flow

Indirect Method

	€m (IFRS figures)

	Quarter				Nine Months
3Q17	2Q18	3Q18		2017	2018
301	570	514	Ebit	769	1,404
178	171	171	Depreciation, Amortisation and Impairments	569	519
(107)	(163)	(163)	Corporate income taxes and oil and gas production taxes	(304)	(418)
13	67	7	Dividends from associates	99	74
13	(41)	(186)	Change in Working Capital	(60)	(387)
398	604	343	Cash flow from operations	1,074	1,192
(19)	(7)	(10)	Net financial expenses	(59)	(64)
(216)	(199)	(246)	Net capex1	(567)	(614)
164	398	87	Free cash flow	448	514
(208)	(252)	(239)	Dividends paid	(423)	(491)
(44)	146	(153)	Post-dividend free cash flow	25	22
(65)	2	(9)	Others2	(121)	(36)
110	(148)	162	Change in net debt	96	14

¹ Net capex based on cash inflows/outflows during the period. 2 Includes CTAs (Cumulative Translation Adjustment) and partial reimbursement of the loan granted to Sinopec of €26 m and €52 m during 3Q18 and 9M18, respectively.

Third quarter

Cash flow from operations (CFFO) of €343 m was impacted by the working capital increase of €186 m, driven by the build-up in inventories in preparation for refining maintenance activities and E&P in-transit crude cargoes.

Dividends paid during the third quarter amounted to €239 m, mainly related to the payment of the interim dividend of the 2018 financial year.

Nine months

During the period, the robust performance across all business segments contributed to the 11% increase in CFFO, reaching €1,192 m, despite the €387 m build in working capital.

Despite net capex of €614 m and dividends paid during the period, free cash flow post-dividend was positive by €22 m.

Direct Method

€m (IFRS figures)

	Quarter			Nine Months
3Q17	2Q18	3Q18		2017	2018
902	1,048	1,331	Cash and equivalents at the beginning of the period1	923	1,096
4,282	5,050	5,333	Received from customers	12,993	14,671
(2,672)	(3,109)	(3,491)	Paid to suppliers	(8,267)	(9,452)
(71)	(97)	(73)	Staff related costs	(240)	(245)
13	67	7	Dividends from associates	99	74
(657)	(691)	(604)	Taxes on oil products (ISP)	(2,009)	(1,940)
(411)	(453)	(665)	VAT, Royalties, PIS, Cofins, Others	(1,219)	(1,497)
(107)	(163)	(163)	Corporate income taxes and oil and gas production taxes	(304)	(418)
377	604	343	Cash flow from operations	1,053	1,192
(253)	(199)	(246)	Net capex2	(581)	(614)
(8)	(7)	(10)	Net Financial Expenses	(81)	(64)
(208)	(252)	(239)	Dividends paid	(423)	(491)
(93)	146	(153)	Post-dividend free cash flow	(33)	22
(50)	127	165	Net new loans	(82)	239
0	26	26	Sinopec loan reimbursement	42	52
(13)	(16)	(26)	FX changes on cash and equivalents	(104)	(66)
746	1,331	1,343	Cash and equivalents at the end of the period1	746	1,343

¹ Cash and equivalents differ from the Balance Sheet amounts due to IAS 7 classification rules. The difference refers to overdrafts which are considered as debt in the Balance Sheet and as a deduction to cash in the Cash Flow Statement. ² Net capex based on cash inflows/outflows during the period.

5.4. Financial position and debt

€m (IFRS figures)

	31 Dec. 2017	30 Jun. 2018	30 Sep. 2018	Var. vs 31 Dec. 2017	Var. vs 30 Jun. 2018
Net fixed assets	7,231	7,095	7,157	(74)	62
Working capital	584	785	971	387	186
Loan to Sinopec	459	451	172	(287)	(279)
Other assets (liabilities)	(613)	(601)	(595)	18	7
Capital employed	7,661	7,730	7,705	44	(25)
Short term debt	551	708	563	13	(145)
Medium-Long term debt	2,532	2,514	2,686	154	171
Total debt	3,083	3,222	3,249	166	27
Cash and equivalents	1,198	1,485	1,350	153	(135)
Net debt	1,885	1,737	1,899	14	162
Total equity	5,776	5,993	5,806	30	(187)
Total equity and net debt	7,661	7,730	7,705	44	(25)

On September 30, 2018 net fixed assets were €7,157 m, up €62 m QoQ, with net capex more than offsetting DD&A and the asset base devaluation from a weaker BRL. Work-inprogress, mainly related to the E&P business, stood at €2,241 m at the end of the quarter.

The loan to Sinopec was reduced by €279 m during the quarter, against a capital reduction of the same amount in Galp/Sinopec JV.

Financial debt

€m (except otherwise stated)

	31 Dec. 2017	30 Jun. 2018	30 Sep. 2018	Var. vs 31 Dec. 2017	Var. vs 30 Jun. 2018
Bonds	1,987	2,042	2,141	154	100
Bank loans and other debt	1,096	1,181	1,108	12	(73)
Cash and equivalents	(1,198)	(1,485)	(1,350)	(153)	135
Net debt	1,885	1,737	1,899	14	162
Average life (years)	2.5	2.9	3.0	0.5	0.0
Average funding cost	3.46%	2.75%	2.63%	(0.83 p.p.)	(0.12 p.p.)
Debt at floating rate	40%	44%	48%	-	-
Net debt to Ebitda RCA	1.1x	0.9x	0.9x	-	-

On September 30, 2018 net debt was €1,899 m, up €162 m QoQ, driven by the dividend and the Brazil bid round payments in September. Net debt to Ebitda RCA stood at 0.9x.

During the third quarter of 2018, Galp issued medium and long term debt amounting to €300 m, which contributed to the increase in the average life of debt to 3.0 years, and decrease in average funding cost to 2.6%. At the end of the period, medium and long term debt accounted for 83% of total debt.

At the end of September, Galp had unused credit lines of approximately €1.4 bn, of which c.75% was contractually guaranteed.

Debt maturity profile

5.5. Reconciliation of IFRS and RCA figures

Ebitda by segment

€m

		Third Quarter			2018	Nine Months
Ebitda IFRS	Inventory effect	Ebitda RC	Non-recurring items	Ebitda RCA		Ebitda IFRS	Inventory effect	Ebitda RC	Non-recurring items	Ebitda RCA
686	(45)	641	0	642	Galp	1,924	(169)	1,754	(30)	1,725
396	-	396	-	396	E&P	1,100	-	1,100	-	1,100
235	(40)	195	0	195	R&M	679	(158)	521	(30)	491
49	(5)	44	-	44	G&P	123	(12)	112	-	112
6	-	6	-	6	Others	21	-	21	-	21

€m

		Third Quarter			2017	Nine Months
Ebitda IFRS	Inventory effect	Ebitda RC	Non-recurring items	Ebitda RCA		Ebitda IFRS	Inventory effect	Ebitda RC	Non-recurring items	Ebitda RCA
479	(13)	466	0	466	Galp	1,338	(31)	1,307	3	1,310
204	-	204	0	204	E&P	554	-	554	0	554
230	(15)	215	0	215	R&M	655	(28)	627	3	630
38	2	40	-	40	G&P	108	(4)	105	-	105
7	-	7	-	7	Others	21	-	21	-	21

Ebit by segment

€m

		Third Quarter			2018	Nine Months
Ebit IFRS	Inventory effect	Ebit RC	Non-recurring items	Ebit RCA		Ebit IFRS	Inventory effect	Ebit RC	Non-recurring items	Ebit RCA
514	(45)	470	0	470	Galp	1,404	(169)	1,235	(30)	1,205
311	-	311	-	311	E&P	849	-	849	-	849
154	(40)	115	0	115	R&M	429	(158)	271	(30)	242
44	(5)	39	-	39	G&P	108	(12)	96	-	96
5	-	5	-	5	Others	18	-	18	-	18

€m

Third Quarter						2017	Nine Months
	Ebit IFRS	Inventory effect	Ebit RC	Non-recurring items	Ebit RCA		Ebit IFRS	Inventory effect	Ebit RC	Non-recurring items	Ebit RCA
	301	(13)	288	1	289	Galp	769	(31)	738	7	745
	115	-	115	0	115	E&P	267	-	267	2	269
	147	(15)	131	1	132	R&M	390	(28)	362	7	369
	34	2	36	(0)	36	G&P	95	(4)	92	(1)	90
	6	-	6	-	6	Others	18	-	18	-	18

Non-recurring items

€m

	Quarter			Nine Months
3Q17	2Q18	3Q18		2017	2018
0.5	(30.1)	0.4	Non-recurring items impacting Ebitda	3.0	(29.7)
0.0	-	-	Accidents caused by natural events and insurance compensation	0.1	-
0.0	-	-	Gains/losses on disposal of assets	(0.7)	-
(0.0)	-	-	Asset write-offs	(0.0)	-
-	1.3	0.4	Employee restructuring charges	-	1.7
0.4	(31.4)	-	Litigation costs (revenues)	3.6	(31.4)
0.5	-	-	Non-recurring items impacting non-cash costs	4.1	-
0.1	-	-	Provisions for environmental charges and others	1.2	-
0.4	-	-	Asset impairments	2.9	-
3.2	0.3	0.3	Non-recurring items impacting financial results	(10.9)	7.5
3.2	0.3	0.3	Gains/losses on financial investments1	(10.9)	7.5
9.8	19.0	9.6	Non-recurring items impacting taxes	52.2	60.2
(0.3)	9.5	(0.0)	Income taxes on non-recurring items	(1.8)	9.5
10.0	9.4	9.7	Energy sector contribution taxes	54.0	50.7
0.1	(0.1)	(0.0)	Non-controlling interests	0.3	(0.1)
14.0	(10.8)	10.3	Total non-recurring items	48.6	37.9

1 Includes CESE impact on GGND.

5.6. IFRS consolidated income statement

€m
	Quarter			Nine Months
3Q17	2Q18	3Q18		2017	2018
3,744	4,380	4,386	Sales	11,058	12,484
147	166	154	Services rendered	456	493
27	76	21	Other operating income	83	157
3,918	4,622	4,561	Total operating income	11,597	13,134
(2,953)	(3,311)	(3,338)	Inventories consumed and sold	(8,775)	(9,557)
(377)	(459)	(432)	Materials and services consumed	(1,184)	(1,336)
(86)	(73)	(88)	Personnel costs	(233)	(243)
(7)	(2)	(5)	Impairments on accounts receivable	(15)	(11)
(17)	(36)	(13)	Other operating costs	(52)	(64)
(3,439)	(3,881)	(3,875)	Total operating costs	(10,259)	(11,211)
479	741	686	Ebitda	1,338	1,924
(177)	(171)	(172)	Depreciation, Amortisation and Impairments	(569)	(519)
(1)	(0)	(0)	Provisions	0	(0)
301	570	514	Ebit	769	1,404
37	35	39	Net income from associates	124	106
(16)	36	(34)	Financial results	(42)	(6)
8	13	12	Interest income	22	31
(26)	(22)	(30)	Interest expenses	(81)	(71)
18	13	3	Capitalised interest	64	30
5	(5)	(15)	Exchange gain (loss)	(9)	(33)
(18)	37	(7)	Mark-to-market of hedging derivatives	(25)	43
(3)	-	4	Other financial costs/income	(13)	(6)
321	641	520	Income before taxes	851	1,504
(133)	(253)	(232)	Taxes1	(376)	(636)
(10)	(10)	(10)	Energy sector contribution taxes2	(54)	(51)
178	378	278	Income before non-controlling interests	422	817
(24)	(48)	(43)	Profit attributable to non-controlling interests	(53)	(120)
154	330	235	Net income	368	697

1 Includes corporate income taxes and taxes payable on oil and gas production, namely Special Participation Tax (Brazil) and IRP (Angola). 2 Includes €15.4 m, €26.6 m and €8.7 m related to the CESE I, CESE II and FNEE, respectively, during the first nine months of 2018.

5.7. Consolidated financial position

€m

	31 Dec. 2017	30 Jun. 2018	30 Sep. 2018
Assets
Tangible fixed assets	5,193	4,921	5,115
Goodwill	84	84	84
Other intangible fixed assets	407	436	526
Investments in associates	1,483	1,554	1,309
Investments in other participated companies	3	3	3
Receivables	254	248	249
Deferred tax assets	350	338	353
Financial investments	32	61	77
Total non-current assets	7,806	7,645	7,716
Inventories1	970	1,040	1,325
Trade receivables	1,018	1,267	1,178
Other receivables	531	743	667
Loan to Sinopec	459	451	172
Financial investments	66	155	271
Current Income tax recoverable	4	16	8
Cash and equivalents	1,197	1,485	1,350
Total current assets	4,245	5,157	4,971
Total assets	12,051	12,802	12,687
Equity and liabilities
Share capital	829	829	829
Share premium	82	82	82
Translation reserve	(151)	(252)	(304)
Other reserves	2,687	2,688	2,687
Hedging reserves	5	13	13
Retained earnings	269	636	408
Profit attributable to equity holders of the parent	623	462	697
Equity attributable to equity holders of the parent	4,344	4,457	4,412
Non-controlling interests	1,435	1,536	1,394
Total equity	5,779	5,993	5,806
Liabilities
Bank loans and overdrafts	937	969	1,042
Bonds	1,595	1,544	1,644
Other payables	286	292	130
Retirement and other benefit obligations	326	330	333
Deferred tax liabilities	76	85	159
Other financial instruments	3	25	30
Provisions	619	644	652
Total non-current liabilities	3,842	3,889	3,990
Bank loans and overdrafts	159	212	66
Bonds	392	497	498
Trade payables	889	1,070	926
Other payables2	854	884	1,122
Other financial instruments	21	86	105
Income tax payable	115	171	174
Total current liabilities	2,430	2,920	2,891
Total liabilities	6,272	6,809	6,880
Total equity and liabilities	12,051	12,802	12,687

1 Includes €85.4 m in inventories from third parties on 30 September 2018.

2 Includes €5.5 m in advanced payments related to inventory from third parties on 30 September 2018.

6. Basis of presentation

Galp's consolidated financial statements have been prepared in accordance with IFRS. The financial information in the consolidated income statement is reported for the quarters ended on September 30, 2018 and 2017, and June 30, 2018. The information in the consolidated financial position is reported as of September 30 and June 30, 2018 and as of 31 December 2017.

Galp's financial statements are prepared in accordance with IFRS, and the cost of goods sold is valued at weighted-average cost. When goods and commodity prices fluctuate, the use of this valuation method may cause volatility in results through gains or losses in inventories, which do not reflect the Company's operating performance. This is called the inventory effect.

Another factor that may affect the Company's results, without being an indicator of its true performance, is the set of non-recurring material items considering the Group's activities.

For the purpose of evaluating Galp's operating performance, RCA profitability measures exclude non-recurring items and the inventory effect, the latter because the cost of goods sold and materials consumed has been calculated according to the Replacement Cost (RC) valuation method.

Recent changes

With effect from January 1, 2018, Galp started considering as operating costs all expenditures incurred with G&G and G&A costs in the exploration activities. Other expenses in the exploration stage, including exploratory wells, continue to be capitalised and written-off when dry.

In addition to those costs, the G&A expenses that transferred from the exploration phase to the stage of development were adjusted under equity. This new policy was applied retrospectively and the comparable figures of 2017 were restated.

Effective from 1 January 2018, impairments on account receivables are accounted for at the Ebitda level, providing a better proxy for the cash generation of each business. Figures of 2017 were restated for comparison purposes.

Starting in 2018, Galp adopted IFRS 9, changing the calculation method for impairments on receivables based on expected losses, and taking into account the credit risk assessment from the beginning. This impact was not applied to 2017 figures.

The Company also implemented IFRS 15, which did not impact materially the Group's results. However, it should be noted that under and overlifting positions in the E&P business started to be accounted as other operating costs/income. This change was not applied to 2017 figures.

7. Definitions

Benchmark refining margin

The benchmark refining margin is calculated with the following weighting: 45% hydrocracking margin + 42.5% cracking margin + 7% base oils + 5.5% Aromatics.

Rotterdam hydrocracking margin

The Rotterdam hydrocracking margin has the following profile: -100% Brent dated, +2.2% LPG FOB Seagoing (50% Butane + 50% Propane), +19.1% EuroBob NWE FOB Bg, +8.7% Naphtha NWE FOB Bg, +8.5% Jet NWE CIF, +45.1% ULSD 10 ppm NWE CIF, +9.0% LSFO 1% FOB Cg; C&L: 7.4%; Terminal rate: \$1/ton; Ocean loss: 0.15% over Brent; Freight 2018: WS Aframax (80 kts) Route Sullom Voe / Rotterdam – Flat \$7.59/ton. Yields in % of weight.

Rotterdam cracking margin

The Rotterdam cracking margin has the following profile: -100% Brent dated, +2.3% LPG FOB Seagoing (50% Butane + 50% Propane), +25.4% EuroBob NWE FOB Bg, +7.5% Naphtha NWE FOB Bg, +8.5% Jet NWE CIF, +33.3% ULSD 10 ppm NWE CIF, +15.3% LSFO 1% FOB Cg; C&L: 7.7%; Terminal rate: \$1/ton; Ocean loss: 0.15% over Brent; Freight 2018: WS Aframax (80 kts) Route Sullom Voe / Rotterdam – Flat \$7.59/ton. Yields in % of weight.

Rotterdam base oils margin

Base oils refining margin: -100% Arabian Light, +3.5% LGP FOB Seagoing (50% Butane + 50% Propane), +13% Naphtha NWE FOB Bg, +4.4% Jet NWE CIF, 34% ULSD 10 ppm NWE CIF, +4.5% VGO 1.6% NWE FOB Cg,+ 14% Base Oils FOB, +26% HSFO 3.5% NWE Bg; Consumptions: -6.8% LSFO 1% CIF NWE Cg; C&L: 7.4%; Terminal rate: \$1/ton; Ocean loss: 0.15% over Arabian Light; Freight 2018: WS Aframax (80 kts) Route Sullom Voe / Rotterdam – Flat \$7.59/ton. Yields in % of weight.

Rotterdam aromatics margin

Rotterdam aromatics margin: -60% EuroBob NWE FOB Bg, -40% Naphtha NWE FOB Bg, +37% Naphtha NWE FOB Bg, +16.5% EuroBob NWE FOB Bg, +6.5% Benzene Rotterdam FOB Bg, +18.5% Toluene Rotterdam FOB Bg, +16.6% Paraxylene Rotterdam FOB Bg, +4.9% Ortoxylene Rotterdam FOB Bg; Consumption: -18% LSFO 1% CIF NEW. Yields in % of weight.

Replacement cost (RC)

According to this method of valuing inventories, the cost of goods sold is valued at the cost of replacement, i.e. at the average cost of raw materials of the month when sales materialise irrespective of inventories at the start or end of the period. The Replacement Cost Method is not accepted by the IFRS and is consequently not adopted for valuing inventories. This method does not reflect the cost of replacing other assets.

Replacement cost adjusted (RCA)

In addition to using the replacement cost method, RCA items exclude non-recurrent events such as capital gains or losses on the disposal of assets, extraordinary taxes, impairment or reinstatement of fixed assets and environmental or restructuring charges which may affect the analysis of the Company's profit and do not reflect its operational performance.

ACRONYMS

%: Percentage +: plus APETRO: Associação Portuguesa de Empresas Petrolíferas (Portuguese association of oil companies) bbl: barrel of oil Bg: Barges bn: billion boe: barrels of oil equivalent BRL: Brazilian real c.: circa CESE: Contribuição Extraordinária sobre o Sector Energético (Portuguese Extraordinary Energy Sector Contribution) CFFO: Cash flow from operations Cg: Cargoes CIF: Costs, Insurance and Freights Cofins: Contribuição para Financiamento da Seguridade Social (Brazil) CORES: Corporación de Reservas Estratégicas de Produtos Petrolíferos (Spain) CTA: Cumulative Translation Adjustment C&L: Consumptions & Losses DD&A: Depreciation, Depletion and Amortisation E&P: Exploration & Production Ebit: Earnings before interest and taxes Ebitda: Ebit plus depreciation, amortisation and provisions EUR/€: Euro EWT: Extended Well Test FNEE: Fondo Nacional de Eficiência Energética (Spain) FOB: Free on board FPSO: Floating, production, storage and offloading unit FX: Foreign exchange Galp, Company or Group: Galp Energia, SGPS, S.A., subsidiaries and participated companies G&A: general and administrative G&G: geology and geophysics G&P: Gas & Power

GGND: Galp Gás Natural Distribuição, S.A. GWh Gigawatt per hour HC: Hydrocracker IAS: International Accounting Standards IFRS: International Financial Reporting Standards IRP: Oil income tax (Oil tax payable in Angola) ISP: Tax on oil products (Portugal) k: thousand kboepd: thousands of barrels of oil equivalent per day kbpd: thousands of barrels of oil per day LNG: liquefied natural gas LSFO: low sulphur fuel oil m: million MIBGAS: Iberian Market of Natural Gas mmbbl: million barrels of oil mmboe: millions of barrels of oil equivalent mmbtu: million British thermal units mm³: million cubic metres mton: millions of tonnes mtpa: million tonnes per annum MWh: Megawatt per hour NE: Net entitlement NG: natural gas n.m.: not meaningful NWE: Northwestern Europe PIS: Programas de Integração Social (Brazil) p.p.: percentage point R&M: Refining & Marketing RC: Replacement Cost RCA: Replacement Cost Adjusted SEM: Successful Efforts Method SPA: Sales and Purchase Agreement SPT: Special participation tax ton: tonnes TTF: Title Transfer Facility ULSD: Ultra low sulphur diesel USA: United States of America USD/\$: Dollar of the United States of America VAT: value-added tax WI: working interest YoY: year-on-year

CAUTIONARY STATEMENT

This report has been prepared by Galp Energia SGPS, S.A. ("Galp" or the "Company") and may be amended and supplemented.

This report does not constitute or form part of and should not be construed as, an offer to sell or issue or the solicitation of an offer to buy or otherwise acquire securities of the Company or any of its subsidiaries or affiliates in any jurisdiction or an inducement to enter into investment activity in any jurisdiction. Neither this report nor any part thereof, nor the fact of its distribution, shall form the basis of, or be relied on in connection with, any contract or commitment or investment decision whatsoever in any jurisdiction.

This report may include forward-looking statements. Forward-looking statements are statements other than in respect of historical facts. The words "believe", "expect", "anticipate", "intends", "estimate", "will", "may", "continue", "should" and similar expressions usually identify forward-looking statements. Forward-looking statements may include statements regarding: objectives, goals, strategies, outlook and growth prospects; future plans, events or performance and potential for future growth; liquidity, capital resources and capital expenditures; economic outlook and industry trends; energy demand and supply; developments of Galp's markets; the impact of regulatory initiatives; and the strength of Galp's competitors.

The forward-looking statements in this report are based upon various assumptions, many of which are based, in turn, upon further assumptions, including without limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties. Although Galp believes that these assumptions were reasonable when made, these assumptions are inherently subject to significant known and unknown risks, uncertainties, contingencies and other important factors which are difficult or impossible to predict and are beyond its control. No assurance, however, can be given that such expectations will prove to have been correct. Important factors that may lead to significant differences between the actual results and the statements of expectations about future events or results include the Company's business strategy, industry developments, financial market conditions, uncertainty of the results of future projects and operations, plans, objectives, expectations and intentions, among others. Such risks, uncertainties, contingencies and other important factors could cause the actual results of Galp or the industry to differ materially from those results expressed or implied in this report by such forward-looking statements.

Real future income, both financial and operating; an increase in demand and change to the energy mix; an increase in production and changes to Galp's portfolio; the amount and various costs of capital, future distributions; increased resources and recoveries; project plans, timing, costs and capacities; efficiency gains; cost reductions; integration benefits; ranges and sale of products; production rates; and the impact of technology can differ substantially due to a number of factors. These factors may include changes in oil or gas prices or other market conditions affecting the oil, gas, and petrochemical industries; reservoir performance; timely completion of development projects; war and other political or security disturbances; changes in law or government regulation, including environmental regulations and political sanctions; the outcome of commercial negotiations; the actions of competitors and customers; unexpected technological developments; general economic conditions, including the occurrence and duration of economic recessions; unforeseen technical difficulties; and other factors.

The information, opinions and forward-looking statements contained in this report speak only as at the date of this report, and are subject to change without notice. Galp and its respective representatives, agents, employees or advisors do not intend to, and expressly disclaim any duty, undertaking or obligation to, make or disseminate any supplement, amendment, update or revision to any of the information, opinions or forward-looking statements contained in this report to reflect any change in events, conditions or circumstances.

Galp Energia, SGPS, S.A. Investor Relations

Pedro Dias, Head Otelo Ruivo, IRO Cátia Lopes João G. Pereira João P. Pereira Teresa Rodrigues Contacts: Tel: +351 21 724 08 66 Fax: +351 21 724 29 65

Address: Rua Tomás da Fonseca, Torre A, 1600-209 Lisboa, Portugal Website: www.galp.com Email:investor.relations@galp.com

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